Streamer design for geophysical prospecting

ABSTRACT

An apparatus is disclosed that includes a solid-core streamer with particle motion sensors disposed within the solid core. Some embodiments may additionally include one or more pressure sensors that are disposed outside of the solid core. In some embodiments, the apparatus may also include one or more electromagnetic sensors. Also disclosed are various methods of operating an apparatus that includes a streamer with particle motion sensors disposed within the solid core of the streamer.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of Provisional Patent ApplicationNo. 61/774,327 filed Mar. 7, 2013, which is incorporated by referenceherein in its entirety.

BACKGROUND

This application generally relates to the field of geophysicalprospecting. More specifically, the application relates to the field ofstreamer design. An apparatus that includes a solid-core streamer withparticle motion sensors in the core is disclosed. Methods of operatingthe apparatus are also disclosed.

In the oil and gas exploration industry, marine geophysical prospectingis commonly used in the search for hydrocarbon-bearing subterraneanformations. Marine geophysical prospecting techniques may yieldknowledge of the subsurface structure of the Earth, which is useful forfinding and extracting hydrocarbon deposits such as oil and natural gas.Seismic and electromagnetic surveying are two of the well-knowntechniques of geophysical prospecting.

For example, in a seismic survey conducted in a marine environment(which may include saltwater, freshwater, and/or brackish waterenvironments), one or more seismic energy sources are typicallyconfigured to be submerged and towed by a vessel. The vessel istypically also configured to tow one or more (typically a plurality of)laterally spaced streamers through the water.

Some techniques of geophysical prospecting involve the simultaneous useof seismic and electromagnetic survey equipment. For example, duringsuch a survey, equipment that includes streamers with electromagneticsensors may be similarly towed behind a vessel. Electromagneticsurveying includes imparting an electric field or a magnetic field intothe Earth's subterranean formations and measuring components of theresultant electromagnetic fields. Data collected during such a marinegeophysical survey may be analyzed to locate hydrocarbon-bearinggeological structures, and thus determine where deposits of oil andnatural gas may be located.

A seismic survey commonly employs seismic energy sources such as anarray of air guns that produce a seismic wavefield when activated. Asused herein, a “wavefield” is a component of seismic data which can berepresented by a single velocity field with vertical and lateralvariations. In a marine seismic survey, the wavefield typically travelsdownward through a body of water overlying the subsurface of the earth.Upon propagating into the Earth, the seismic wavefield is then at leastpartially reflected by subsurface reflectors. Such reflectors aretypically those interfaces between subterranean formations havingdifferent elastic properties such as density and sound wave velocity,which may lead to differences in acoustic impedance at the interfaces.The reflected seismic wavefield is detected by the sensors such asparticle motion sensors and/or pressure sensors in the seismicstreamers. A record is made in the recording system of the signalsdetected by each sensor (or by groups/networks of such sensors). Therecorded signals are thereafter interpreted to infer the structure andcomposition of the subterranean formation.

A typical streamer may be quite long, typically multiple kilometers inlength. Some geophysical surveys may be conducted with a singlestreamer, while some surveys use multiple streamer systems including oneor more arrays of streamers. The individual streamers in such arrays aregenerally affected by the same types of forces that affect a singlestreamer.

One of the most common types of pressure sensor used in marinegeophysical surveying is a hydrophone. A hydrophone is generallyunderstood to be an omnidirectional device. Such hydrophones thereforegenerally cannot distinguish between the directions of the up-going anddown-going wavefields. In particular, seismic energy directly reachingthe hydrophones from the source cannot be easily distinguished from thevarious reflections from the surface of the water and the seafloor(e.g., the “source ghost” and the “receiver ghost”). As a consequence,wavefields of both the source and receiver ghost may interfere withprimary reflections, which contain the desired information about thesubterranean formations, reducing seismic image resolution and reducingthe usefulness of seismic data for reservoir delineation andcharacterization.

Due to the omnidirectional reception nature of hydrophones, particlemotion sensors have also been employed to detect vector quantitiesduring marine seismic survey operations. The term “particle motionsensor” should be understood in the context of this disclosure asreferring to any of various types of sensors, including velocity meters,accelerometers, geophones, pressure gradient sensors, particledisplacement sensors, etc.

In a multi-component streamer that includes both pressure sensors andparticle motion sensors, the combination of signals from pressure andparticle motion sensors may be used to remove the “ghosting” effectsduring seismic data processing. One example of this is described in U.S.Pat. No. 7,684,281, which is incorporated herein by reference in itsentirety.

The design of a multi-component streamer thus may take into accountmultiple factors, including the different responses and noisecharacteristics of pressure sensors and particle motion sensors, andalso electromagnetic sensors. It is desirable for a streamer to bedurable and less prone to mechanical and other sources of noise.Improvements may also be desirable in areas such as signal-to-noiseratio (e.g., for both pressure sensors and particle motion sensors),diameter (e.g., a reduced diameter may give reduced drag and easierhandling), robustness, etc.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an example of a marine data acquisition system using anapparatus according to one embodiment of the disclosure.

FIG. 2 shows a cross section of an apparatus according to one embodimentof the disclosure.

FIG. 3 is a perspective view of the embodiment shown in FIG. 2.

FIG. 4 shows a method according to one embodiment of the disclosure.

DETAILED DESCRIPTION

This specification includes references to “one embodiment” or “anembodiment.” The appearances of the phrases “in one embodiment” or “inan embodiment” do not necessarily refer to the same embodiment.Particular features, structures, or characteristics may be combined inany suitable manner consistent with this disclosure.

This specification may use phrase such as “based on.” As used herein,this term is used to describe one or more factors that affect adetermination. This term does not foreclose additional factors that mayaffect a determination. That is, a determination may be solely based onthose factors or based only in part on those factors. Consider thephrase “determine A based on B.” This phrase connotes that B is a factorthat affects the determination of A, but does not foreclose thedetermination of A from also being based on C. In other instances, A maybe determined based solely on B.

Various devices, units, circuits, or other components may be describedor claimed as “configured to” perform a task or tasks. In such contexts,“configured to” is each used to connote structure by indicating that thedevices/units/circuits/components include structure that performs thetask or tasks during operation. As such, thedevice/unit/circuit/component can be said to be configured to performthe task even when the specified device/unit/circuit/component is notcurrently operational (e.g., is not on or in operation). Thedevices/units/circuits/components used with the “configured to” languageinclude hardware—for example, circuits, memory storing programinstructions executable to implement the operation, etc. Reciting that adevice/unit/circuit/component is “configured to” perform one or moretasks is expressly intended not to invoke 35 U.S.C. §112(f), for thatdevice/unit/circuit/component.

In some embodiments, various items of information relating togeophysical surveying may be embodied in a geophysical data product. A“geophysical data product” may be stored on a computer-readable,non-transitory medium and may embody geophysical data (such as rawstreamer data, processed streamer data, two- or three-dimensional mapsbased on streamer data, etc.). Some non-limiting examples ofcomputer-readable media may include hard drives, CDs, DVDs, print-outs,etc. In some embodiments, raw analog data from streamers may be storedas a geophysical data product. In other instances, the data may first bedigitized and/or conditioned prior to being stored as the geophysicaldata product. In yet other instances, the data may be fully processedinto a two- or three-dimensional map of the various geophysicalstructures before being stored in the geophysical data product. Thegeophysical data product may be produced offshore (i.e. by equipment ona vessel) or onshore (i.e. at a facility on land) either within theUnited States or in another country. If the geophysical data product isproduced offshore or in another country, it may be imported onshore to afacility in the United States. Once onshore in the United States,geophysical analysis may be performed on the geophysical data product.

A typical streamer generally includes a flexible tubular structure whichmay be made from polymeric materials such as polyurethane. One or morestress members, generally made of synthetic fiber or other materialswith high tensile strength, may be disposed within the tubular structureof the streamer. These stress members generally run along the entirelength of the streamer (in known devices, typically along the centrallongitudinal axis of the streamer) and serve as the main stress-bearingcomponent of the streamer. Typical streamers also generally include oneor more types of wiring configured to transmit data and/or power (inknown devices, typically also disposed along the central longitudinalaxis of the streamer). Streamers may additionally include an exteriorjacket or sheath, at least partially covering the exterior of thestreamer. The exterior jacket is commonly made of a thermoplasticmaterial.

In some instances, a streamer may contain a solid inner portion,sometimes referred to as the solid “core.” The solid core may be agenerally cylindrical structure with an outer diameter smaller than anouter tubular structure of the solid streamer. The solid core may bemade from materials such as molded or extruded material includingthermoplastic polymers. In some cases, such molded or extruded materialmay initially be in a liquid state. Upon cooling, such material maysubsequently become solid. (A “solid” core does not necessarily meanthat the core is rigid, incompressible, or inflexible. Solid cores areoften bendable, compressible, and/or flexible. Likewise, a “solid” coremay not completely fill the interior volume, but the core may have airbubbles as in a static foam, or other cut-outs or voids.) An annularspace between the outer structure and the solid core may also in someinstances be filled with a solid material, which may or may not be thesame as the solid material in the core.

FIG. 1 shows an exemplary marine seismic survey system as it istypically used in acquiring geophysical data for a survey. Vessel 14 maymove along a surface of body of water 11 such as a lake or the ocean.Vessel 14 may include source actuation, data recording, and navigationequipment, shown generally at 12 and referred to for convenience as a“recording system.” Vessel 14 (or a different vessel, not shown) may beconfigured to tow one or more energy sources 33 (e.g., a seismic energysource), or arrays of such energy sources in body of water 11. Vessel 14or the different vessel may tow one or more streamers 40 near thesurface of the body of water 11. The streamers 40 may extend behindvessel 14 for several kilometers. Each streamer 40 may further containvarious types of sensors (e.g., pressure sensors, particle motionsensors, electromagnetic sensors, etc.), stress members, wiring (e.g.,data and/or power wiring), and other components.

In accordance with some embodiments, streamer 40 may be amulti-component streamer, containing both particle motion sensors andpressure sensors, and in some embodiments also electromagnetic sensors.The pressure and particle motion sensors may be configured to detect aseismic wavefield, and the electromagnetic sensors may be configured todetect electromagnetic fields. Pressure sensors may be configured todetect a scalar-valued wavefield, and particle motion sensors may beconfigured to detect a vector-valued wavefield. The configuration ofsome embodiments of streamer 40 will be explained in more detail belowwith reference to FIGS. 2 and 3.

During one embodiment of marine seismic survey operation, seismic energysource 33 may actuate at selected times. When actuated, seismic energysource 33 may produce seismic wavefield 19 that emanates generallyoutwardly from seismic energy source 33. Seismic wavefield 19 may traveldownwardly, through body of water 11, and pass, at least in part,through water bottom 20 into the subterranean formations. Seismicwavefield 19 may be at least partially reflected from one or moreacoustic impedance boundaries below water bottom 20, and may travelupwardly and be detected by sensors in streamers 40. The structure ofthe formations, among other properties of the Earth's subsurface, may beinferred by detections based at least in part on seismic wavefield 19and by characteristics of the detected seismic wavefield, such asamplitude, phase, travel time, etc.

In an alternative embodiment, in addition to pressure sensors andparticle motion sensors, streamer 40 may additionally contain one ormore electromagnetic sensors (not shown). These electromagnetic sensorsmay be configured to measure electromagnetic characteristics of theEarth's subsurface in response to electromagnetic energy sources (alsonot shown). In certain embodiments, the electromagnetic sensors may bedisposed on an outer surface of streamer 40.

The number of streamers, sensors, streamer positioning devices, or otherequipment shown in FIG. 1 is only for purposes of illustration and isnot a limitation on the number of each device that may be used in anyparticular embodiment. The broken lines in the streamers 40 indicatethat this figure is not necessarily drawn to scale.

FIG. 2 illustrates a cross-sectional view of one embodiment of streamer40. As shown, streamer 40 may include a central portion illustrated asincluding solid core 24. One non-limiting embodiment of solid core 24may be a generally cylindrical structure that is bendable, compressible,and/or flexible. Solid core 24 may be situated such that a centrallongitudinal axis 59 of streamer 40 passes through solid core 24 (e.g.,solid core 24 and longitudinal axis 59 may be coaxial). In one suchembodiment, the solid material making up solid core 24 may be a moldedor extruded material, such as a thermoplastic polymer.

Streamer 40 may also include particle motion sensor 50, pressure sensors30, stress member 32, inner wiring 38, outer wiring 39, and exteriorjacket 55. Exterior jacket 55 may be a plastic tubular structuredisposed at least partially around the outer surface of outer portion28. For example, exterior jacket 55 may provide a mesh covering to theouter surface of streamer 40. In some embodiments, exterior jacket 55may have cut-outs intended to expose portions of streamer 40 to water,for example, electromagnetic sensors.

In the embodiment of FIG. 2, a particle motion sensor 50 is disposedwithin solid core 24. Particle motion sensor 50 may be a single particlemotion sensor or one of a group (or network) of particle motion sensorsdisposed at intervals along at least a portion of longitudinal axis 59of streamer 40.

In some embodiments, a group of particle motion sensors 50 may containcircuitry configured to perform analog-to-digital conversion and/orconditioning (e.g. weighting, noise reduction, etc.) of the particlemotion sensor signals. Specifically, such circuitry may be configured tooperate on a single particle motion sensor and/or a plurality ofparticle motion sensors that are wired together (e.g., a plurality ofsensors forming an analog group that is configured to output a signal,which is then digitized and/or conditioned by the circuitry).

In the embodiment illustrated in FIG. 2, particle motion sensor 50 isdisposed in the center of solid core 24. For purposes of thisdisclosure, a statement such as particle motion sensor being disposed inthe “center” of solid core 24 (or other variations of that phraseology)may be taken to mean that longitudinal axis 59 of solid core 24 passesthrough at least a portion of particle motion sensor 50, withoutimplying that particle motion sensor 50 is positioned axiallysymmetrically. In some instances, it may be advantageous forlongitudinal axis 59 to pass through the actual center of particlemotion sensor 50 (e.g., for solid core 24 and particle motion sensor 50to be concentric). In some embodiments, other particle motion sensors 50may be similarly disposed within solid core 24 at selected spacingsalong longitudinal axis 59.

The placement of particle motion sensor 50 at the center of solid core24 may be advantageous for various reasons. For example, such aplacement may decrease the amount of rotation-related noise picked up byparticle motion sensor 50.

In certain embodiments, by molding or otherwise disposing particlemotion sensor 50 in the material of solid core 24, particle motionsensor 50 may be held in place within solid core 24. In an alternativeembodiment, particle motion sensor 50 may be held in place in solid core24 by being molded or otherwise disposed within a polymeric materialdifferent from the molded or extruded material of solid core 24. In yetother embodiments, solid core 24 may have an opening in which theparticle motion sensor 50 may be placed and then secured by a harness,elastic ring, or other method.

In one embodiment, a group of particle motion sensors may includeorthogonally aligned sensors configured to measure mutually orthogonalcomponents of particle motion, and/or sensors aligned to a particularaxis to measure particle motion components along that axis. For example,such sensors may in some instances measure one or more components ofparticle motion along a selected axis (e.g., inline, crossline, andvertical components along corresponding axes), etc. In theseembodiments, each particle motion sensor in the group may be configuredto measure the seismic wavefield at a particular point with respect to aparticular direction or axis. For purposes of this disclosure, “align”or “aligned” may be defined as including situations in which objects aredisposed within about 5° of perfect co-linearity. Further, for purposesof this disclosure, “orthogonal” may be defined as including situationsin which objects are disposed at an angle within about 5° of a rightangle.

In the embodiment illustrated in FIG. 2, the network of particle motionsensors, including particle motion sensor 50 may include inner wiring38, which may be part of the network of particle motion sensors. In someembodiments (e.g., as shown in FIG. 2), inner wiring 38 may be disposedconcentrically around solid core 24 (e.g., between solid core 24 andstress member 32). In other embodiments, inner wiring 38 may be disposedwithin solid core 24. In the cross-section illustrated in FIG. 2,portions of inner wiring 38 are illustrated to represent a helicalwinding of inner wirings 38 concentric with longitudinal axis 59. Aswould be understood by one of ordinary skill in the art with the benefitof this disclosure, helical winding is only one of a variety of suitablemethods for disposing inner wirings 38 in streamer 40. Helical windingmay have the benefit, for example, of allowing streamer 40 to flexwithout compromising the integrity of the connections provided by innerwirings 38. Inner wiring 38 may be configured to be connected toparticle motion sensor 50 mechanically, electrically, optically, and/orby other methods. In some embodiments, inner wiring 38 may also includecables and/or optic fibers. In some embodiments, inner wiring 38 may beconfigured to transport signals from particle motion sensor(s) 50 to anend of streamer 40. In one such embodiment, the end of streamer 40 maybe coupled to vessel 14, such that the signals may be transported torecording system 12 on vessel 14. In some embodiments, the particlemotion sensor signals may include those that have been digitized and/orconditioned in the network of particle motion sensors.

In other embodiments, streamer 40 may be divided into a number ofseparate sections or modules that may be decoupled from one another. Inthese embodiments, inner wiring 38 may be configured to transportparticle motion sensor signals to an end of one such section of thestreamer 40. At the end of each section, the signals may be tied into abackbone network of streamer 40 (not shown). The backbone network inthis embodiment may extend through each of the sections throughout theentire length of streamer 40.

Such a backbone network may be disposed within or outside of solid core24. In other embodiments, streamer 40 may include more than one backbonenetwork (e.g., one backbone network for pressure sensor signals, and aseparate backbone network for particle motion sensor signals).

As noted above, stress members tend to be located at or near the centralaxis of the streamer. As shown in FIG. 2, however, streamer 40 mayinclude stress member 32 disposed around solid core 24. Stress member 32may support the tension along longitudinal axis 59 of streamer 40 (e.g.,tension related to streamer 40 being towed by vessel 14). In someembodiments, stress member 32 may be a rope or a cable that is madeusing high-strength materials such as steel, Kevlar® or other suitablematerials. In some embodiments, stress member 32 may be a layer that hashigh-strength fibers (e.g., fibers 36) disposed within. The placement ofstress member 32 around solid core 24 may provide various advantages,such as increased torsional stiffness. The placement of pressure sensors30 outside of stress member 32 may provide for a higher signal-to-noiseratio in some embodiments.

In certain embodiments, solid core 24 may be disposed at the center ofstress member 32. For example, it may be advantageous for solid core 24and stress member 32 to be concentric. In one embodiment, stress member32 may include a multitude of strands that may be woven around solidcore 24 (e.g., in a cylinder). In other embodiments, one or more stressmembers 32 may be disposed adjacent to solid core 24. In yet anotherembodiment, one or more stress members 32 may be part-wise cylindricalaround solid core 24.

The embodiment of streamer 40 shown in FIG. 2 may further include one ormore pressure sensors 30, each disposed within an outer portion 28 ofstreamer 40. In the embodiment shown in FIG. 2, solid core 24 isconcentric with outer portion 28 along longitudinal axis 59.Alternatively, however, solid core 24 may be disposed off-center withinouter portion 28.

Pressure sensors 30 may be bender hydrophones, cylindrical hydrophones,polyvinylidene fluoride (PVDF) hydrophones, or any other suitablepressure sensors that include a pressure-sensitive element. Pressuresensors 30 may each be configured to detect seismic energy in thewavefield reflected by formations as described in FIG. 1. As one or morepressure sensors 30 may be configured to detect signals that arereflected from the subterranean formations under the water surface, amultiplicity of such sensors in the direction of the reflected signalsmay be beneficial in terms of signal-to-noise ratio. The placement ofpressure sensors 30 outside of stress member 32 may provide increasedsensitivity. Further, it may be even more advantageous to place pressuresensors 30 at or near exterior jacket 55 of streamer 40 for even furtherincreased pressure sensitivity.

One or more pressure sensors 30 may be connected to outer wiring 39disposed within outer portion 28. In some embodiments, outer wiring 39may be disposed within an annular space between solid core 24 and outerportion 28. This annular space may in some instances be filled with thesame material from which solid core 24 is made, the same material fromwhich outer portion 28 is made (e.g., filler material 46), or from someother material. In some instances, solid core 24 and outer portion 28may be made of the same material as one another. Outer wiring 39 mayinclude circuitry (analogous to the circuitry discussed above for theparticle motion sensors) that is configured to perform analog-to-digitalconversion and/or conditioning of pressure sensor signals. Suchcircuitry (and/or various other components) may be powered via outerwiring 39, and may be configured to operate on signals from a singlepressure sensor or from a plurality of pressure sensors. Outer wiring 39may further be configured to transmit signals from the one or morepressure sensors 30 to an end of streamer 40 or an end of a section ofstreamer 40, where the signals may be tied into a backbone network ofstreamer 40. In some embodiments, electromagnetic sensors disposed at ornear the outer surface of streamer 40 may also be connected to outerwiring 39. In the cross-section illustrated in FIG. 2, portions of outerwirings 39 are illustrated to represent a helical winding of outerwirings 39 concentric with longitudinal axis 59. As would be understoodby one of ordinary skill in the art with the benefit of this disclosure,helical winding is only one of a variety of suitable methods fordisposing outer wirings 39 in streamer 40. Helical winding may have thebenefit, for example, of allowing streamer 40 to flex withoutcompromising the integrity of the connections provided by outer wirings39.

Outer portion 28 may be partially or fully filled with filler material46. Filler material 46 may in some instances be made from the same solidfiller material as solid core 24 (e.g., a molded or extruded materialsuch as thermoplastics). In other embodiments, filler material 46 may bea relatively light-weight and low-density material that may provide somebuoyancy to streamer 40. Filler material 46 is shown in FIG. 2 asfilling a plurality of voids within streamer 40. In this particularembodiment, filler material 46 may fill spaces in between componentsdiscussed above including outer portion 28, solid core 24, inner wiring38 and outer wiring 39, stress member 32, and one or more pressuresensors 30. In one embodiment, one or more pressure sensors 30 may besuspended within filler material 46. In another embodiment, pressuresensors 30 may be enclosed in respective housings (not shown) that areembedded or molded in filler material 46.

Turning to FIG. 3, which is a perspective view of a cross-section ofpart of streamer 40 shown in FIG. 2, showing the various components froma different perspective. The uneven line at the bottom of theillustration indicates that only a part of streamer 40 is illustrated,and the dotted lines indicate objects drawn that are otherwise hiddenfrom view.

FIG. 4 is a flow diagram illustrating one exemplary embodiment of amethod 400 for operating an apparatus which includes a solid-corestreamer having one or more particle motion sensors disposed in thecenter of the solid core. The method shown in FIG. 4 may be used inconjunction with any of the computing systems, devices, elements, orcomponents disclosed herein, among other devices. In variousembodiments, some of the method elements shown may be performedconcurrently, in a different order than shown, or may be omitted.Additional method elements may also be performed as desired. Flow beginsat block 410.

At block 410, a vessel tows a solid-core streamer in a body of water.The solid-core streamer may have a solid core that includes one or moreparticle motion sensors in the center of the solid core. The solid-corestreamer may additionally include one or more pressure sensors that aredisposed within the streamer outside of the solid core. Flow proceeds toblock 420.

At block 420, a seismic energy source is actuated and sends a seismicwavefield through the body of water into the subterranean formations.Flow proceeds to block 430. The subterranean formations may reflectportions of the seismic wavefield, which may then be detected by theparticle motion sensors and pressure sensors in the solid-core streamer.At block 430, the one or more pressure sensors transmit signalsindicative of pressure variations, and the particle motion sensorstransmit signals indicative of at least one component of particlemotion. In some embodiments, method 400 ends at 430. In someembodiments, flow proceeds to block 440.

At block 440, a computing system analyzes the transmitted pressuresensor signals and particle motion sensor signals to determine thevertical component of the seismic wavefield. The analysis may includecombining the pressure sensor signals with the signals indicative of avertical component of the motion transmitted by the particle motionsensors in order to determine both an up-going and a down-going seismicwavefield. In some embodiments, flow ends at 440. In some embodiments,flow proceeds to block 450.

At block 450, a geophysical data product may be produced. Thegeophysical data product may include particle motion sensor signals,pressure sensor signals, and/or analyzed particle motion sensor signalsand pressure sensor signals, and the geophysical data product may bestored on a non-transitory, tangible computer-readable medium. Thegeophysical data product may be produced offshore (i.e. by equipment ona vessel) or onshore (i.e. at a facility on land) either within theUnited States or in another country. If the geophysical data product isproduced offshore or in another country, it may be imported onshore to afacility in the United States. Once onshore in the United States,geophysical analysis may be performed on the geophysical data product.

Some embodiments according to this disclosure may optimize the placementof particle motion sensors within a streamer with respect to factorssuch as signal sensitivity, noise, and streamer robustness. Someembodiments may improve signal-to-noise ratio during a geophysicalsurvey, increase data reliability, and reduce survey operation cost,increase survey operation uptime and efficiency.

Although specific embodiments have been described above, theseembodiments are not intended to limit the scope of the presentdisclosure, even where only a single embodiment is described withrespect to a particular feature. Examples of features provided in thedisclosure are intended to be illustrative rather than restrictiveunless stated otherwise. The above description is intended to cover suchalternatives, modifications, and equivalents as would be apparent to aperson skilled in the art having the benefit of this disclosure.

The scope of the present disclosure includes any feature or combinationof features disclosed herein (either explicitly or implicitly), or anygeneralization thereof, whether or not it mitigates any or all of theproblems addressed herein. Various embodiments may provide some, all, ornone of the described advantages. Accordingly, new claims may beformulated during prosecution of this application (or an applicationclaiming priority thereto) to any such combination of features. Inparticular, with reference to the appended claims, features fromdependent claims may be combined with those of the independent claimsand features from respective independent claims may be combined in anyappropriate manner and not merely in the specific combinationsenumerated in the appended claims.

What is claimed is:
 1. An apparatus, comprising: a streamer, wherein thestreamer includes: a solid core through which a longitudinal axis of thestreamer extends, wherein the solid core includes one or more particlemotion sensors disposed along the longitudinal axis; and an outerportion disposed around the solid core, wherein the outer portionincludes one or more pressure sensors.
 2. The apparatus of claim 1,wherein the streamer includes at least one electromagnetic sensor. 3.The apparatus of claim 1, wherein the streamer further includes innerwiring configured to transport signals of the one or more particlemotion sensors.
 4. The apparatus of claim 1, wherein at least one of theparticle motion sensors is disposed in the center of the solid core. 5.The apparatus of claim 1, wherein a stress member of the streamer isdisposed between the solid core and the outer portion.
 6. The apparatusof claim 1, wherein the one or more particle motion sensors include atleast two particle motion sensors that are orthogonally aligned.
 7. Theapparatus of claim 1, wherein the solid core comprises a molded orextruded material.
 8. The apparatus of claim 1, further comprising anexterior jacket disposed around the outer portion.
 9. The apparatus ofclaim 1, wherein the outer portion further includes outer wiringconfigured to transport signals of the one or more pressure sensors. 10.The apparatus of claim 9, wherein the outer wiring is configured tosupply power.
 11. The apparatus of claim 9, wherein the outer wiring iscoupled to a backbone network configured to transport signals of the oneor more pressure sensors to a vessel.
 12. A system, comprising: at leastone streamer; and a vessel configured to tow the at least one streamer;wherein the at least one streamer has a longitudinal axis and includes:a solid core disposed along the longitudinal axis, wherein the solidcore includes one or more particle motion sensors; an outer portiondisposed around the solid core, wherein the outer portion includes oneor more pressure sensors.
 13. The system of claim 12, wherein at leastone stress member is disposed between the solid core and the outerportion.
 14. The system of claim 12, wherein at least one of theparticle motion sensors is disposed in the center of the solid core. 15.The system of claim 12, wherein the outer portion further includes outerwiring configured to transport signals of the one or more pressuresensors.
 16. The system of claim 15, wherein the outer wiring is coupledto a backbone network configured to transport signals of the one or morepressure sensors to the vessel.
 17. The system of claim 12 furthercomprising a computing system configured to analyze signals from theparticle motion sensors and pressure sensors.
 18. A method, comprising:towing one or more streamers behind a vessel, wherein at least onestreamer includes: a solid core through which a longitudinal axis of theat least one streamer extends, wherein the solid core includes one ormore particle motion sensors disposed along the longitudinal axis; andan outer portion disposed around the solid core, wherein the outerportion includes one or more pressure sensors; actuating at least oneseismic energy source; and detecting a seismic wavefield at the one ormore particle motion sensors and the one or more pressure sensors. 19.The method of claim 18, further comprising: transmitting signalsindicative of at least one component of particle motion at the particlemotion sensors; transmitting signals indicative of pressure variationsat the pressure sensors; and analyzing the transmitted particle motionand pressure signals.
 20. The method of claim 19, further comprisingproducing a geophysical data product from the transmitted particlemotion and pressure signals.
 21. The method of claim 20, furthercomprising recording the geophysical data product on a computer-readablemedium suitable for importing onshore.
 22. The method of claim 20,further comprising performing onshore geophysical analysis of thegeophysical data product.